Formation hydraulic fracturing is a well-known method for enhancing hydrocarbons' production from a well by means of fracture generation. A high-viscosity fluid, also referred to as the hydraulic fracturing fluid containing a propping agent (proppant) is injected into a formation to create a fracture in the production interval and fill the fracture with the proppant. For the efficient use the fracture must be located inside the production interval and must not protrude into the adjacent strata as well as be of sufficient length and width. Therefore, obtaining reliable information about hydraulic fractures is, therefore, crucial for optimizing their design and efficient planning of the fields operation.
Nowadays the geometry of fractures is determined using various technologies and methods. Most wide-known are passive seismic methods (the so-called hydraulic fracture visualization) ensuring the evaluation of the spatial orientation of a fracture and its length during the hydraulic fracture activities and based on recording and locating of micro-seismic events generated by cracking of the rock near the edges of propagating fracture. The shape characterization has some intrinsic uncertainty, because the scatter of natural microseismic events around the fractured zone can be large compared to typical fracture width. The method does not always work: due to low emission amplitudes or high attenuation registered signal may be low compared to a noise level. Hydraulic fracture monitoring activities using passive seismics methods are very seriously restricted by the fact that they require a second observation well located within reasonably small distance from the main treatment well. Small distance is required to ensure registration of relatively weak microseimic events, whose amplitude mostly depends on in-situ properties and state of the rock and is out of operator's control. The second well is required, because it is difficult to deploy acquisition string simultaneously with the hydraulic fracturing treatment involving high pressure pumping, which may be very noisy.
Hydraulic fracture seismics using an active seismic source are also known. They may provide a higher (compared with the passive seismics methods) amplitude of the registered useful signal. Thus, U.S. Pat. No. 5,574,218 suggests a method for determining a length and an azimuth of a hydraulic fracture after it has been formed without the need for positioning sensors at subsurface locations by performing two or more subsequent surface seismic acquisitions. The method comprises performing a baseline seismic survey to determine a seismic response of the undisturbed formation followed by one or more seismic surveys when the fracture is still open and under pressure; studying the differences in seismic responses enables to determine the fracture length and azimuth. A seismic source and seismic receivers' array are positioned at substantially equal distances from the treatment well with this distance being equal to approximately one-half of the depth of the layer to be fractured. The method described is not efficient for hydraulic fracture characterization, because, apparently, it aims at registration of the differential signal diffracted from the fracture in upward direction, which will have small amplitude.
In WO 99/04292, it is suggested to detect horizontal and vertical edges of a fracture by identifying a boundary between unaffected and shadowed direct raypaths, when acquisition string and a source are on the opposite sides of the open hydraulic fracture and by distinguishing the raypaths reflected from the fracture from raypaths transmitted in the reservoir on the same side from the fractures as the seismic source. In both cases the detection of the fracture edges is done by detecting absence or presence of an S-component signal completely shadowed or reflected by the open fluid-filled fracture. This method is aimed at the detection of the strongest component of the seismic disturbance introduced by the hydraulic fracture when it is maintained in open condition, this disturbance is the share shadowing by the fracture due to zero elastic shear modulus in the fracture fluid. The described method has very high requirements to the field development diagram and plan, especially as far as the well trajectory is concerned. The method requires several dedicated observation wells, preferably, located within 100 m distance from the treatment well which need to be stopped from production during the survey; to detect shadowed or reflected rays the seismic sensors should be positioned below the fracture. Finding such wells occasionally has quite low chance for success, it is more likely that getting such wells would require costly dedicated drilling program, because typically wells are not drilled far below the production depth.